Reducing sulfide in production fluids during oil recovery

ABSTRACT

Methods are provided for treating production fluid in a production well in an oil reservoir to reduce the amount of sulfide in the production fluid. The production fluid is treated with nitrate and/or nitrite ions or inorganic oxidizing agent in an aqueous solution that is added to the well casing.

This application claims the benefit of U.S. National application Ser. No. 13/226,717, filed Sep. 7, 2011, which is incorporated by reference in its entirety.

FIELD OF THE INVENTION

This disclosure relates to the field of oil recovery. More specifically, it relates to reducing sulfide in production fluids recovered from oil reservoirs.

BACKGROUND OF THE INVENTION

Hydrogen sulfide (H₂S) is commonly found in oil reservoirs due to its production by sulfate-reducing bacteria (SRB), which may be indigenous to an oil reservoir and/or introduced such as during water injection in water flooding secondary oil recovery methods. The metabolism of these SRB converts sulfate that is typically present in injection water to sulfide, which results in souring of a reservoir and the oil produced, thereby reducing the value of the recovered crude oil. In addition sulfide in production water causes corrosion of equipment used to recover oil including storage reservoirs, surface facilities, and pipelines, and it can cause plugging by the formation of iron sulfide, as well as causing health and environmental hazards.

In oil reservoirs and in production and injection fluids either or both of SRB and nitrate-reducing bacteria (NRB) may be present, either as indigenous populations or through introduction. When both are present, there may be competition for nutrients between SRB and nitrate-reducing bacteria (NRB). The presence of SRB and NRB, the presence and types of nutrients available, as well as the balance of sulfate, nitrate, and nitrite are all factors affecting levels of sulfide in the reservoirs and fluids.

One method used to reduce sulfide has been to add nitrate to injection water that is administered field-wide to an oil reservoir through multiple injection wells (Griroryan et al. (2009) J. Can. Petrol Technol. 48:58-61). Injection of water containing nitrate has been tested in continuous or pulsed applications, and when introduced to a portion of a limited section of a reservoir, using nitrate at 150 ppm to 40,000 ppm (Voordouw et al. (2009) Environ. Sci. Technol. 43:9512-9518). Recently it was shown that light components of oil, like toluene, were degraded when nitrate was introduced into a reservoir via injection wells to prevent sulfide formation, because the presence of nitrate in the reservoir for a long period of time was sufficient to encourage growth of oil degrading nitrate reducers (Agrawal, et al. (2011) Abstract Published in the 3^(rd) International Symposium on Applied Microbiology and Molecular Biology in Oil Systems Jun. 13-15, 2011, Calgary, Alberta, Canada). Biodegradation of light oil components is undesirable because this causes increased oil viscosity and the higher viscosity causes increased resistance to oil flow.

U.S. Pat. No. 5,405,531 discloses removing H₂S and preventing SRB production of H₂S in an aqueous system by introducing nitrite and nitrate and/or molybdate ions in concentrations where denitrifying microorganisms outcompete SRB for available nutrients. Generally less than about 3000 ppm of total nitrate and nitrite ions is added to the aqueous system that is then injected into an oil-bearing formation, more particularly between about 25 and 500 ppm. U.S. Pat. No. 7,833,551 discloses inhibiting sulfide production by SRB by treating SRB with a non-oxidizing biocide and a metabolic inhibitor, which requires lower concentrations of biocide and inhibitor than when each is used alone.

There remains a need for additional effective methods to reduce sulfide in production fluid.

SUMMARY OF THE INVENTION

The invention relates to methods that lead to reduced sulfide in production fluid obtained from an oil reservoir. Accordingly, the invention provides a method for treating an oil production well comprising:

-   -   a) providing an oil production well in an oil reservoir having a         well casing and a production pipe;     -   b) adding an aqueous solution comprising at least one inorganic         oxidizing agent to the well casing wherein said solution flows         down the well casing and contacts production fluid in the well         bore below the production pipe ; and     -   c) producing the production fluid through the production pipe;         wherein the sulfide concentration in the production fluid is         reduced as compared to the sulfide concentration in production         fluid obtained with omission of step (b).

In one embodiment the inorganic oxidizing agent is nitrate ions, nitrite ions, or a mixture of nitrate and nitrite ions.

In another embodiment the inorganic oxidizing agent is selected from permanganates, persulfates, inorganic peracids, chromates, bromates, iodates, chlorates, perchlorates, chlorites, hypochlorites, inorganic peroxides, and oxides.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of a production well, the subterranean sites adjacent to the production well, and fluids in the well.

DETAILED DESCRIPTION

Applicants specifically incorporate the entire content of all cited references in this disclosure. Unless stated otherwise, all percentages, parts, ratios, etc., are by weight. Trademarks are shown in upper case. Further, when an amount, concentration, or other value or parameter is given as either a range, preferred range or a list of upper preferable values and lower preferable values, this is to be understood as specifically disclosing all ranges formed from any pair of any upper range limit or preferred value and any lower range limit or preferred value, regardless of whether ranges are separately disclosed. Where a range of numerical values is recited herein, unless otherwise stated, the range is intended to include the endpoints thereof, and all integers and fractions within the range. It is not intended that the scope of the invention be limited to the specific values recited when defining a range.

The following definitions are provided for the special terms and abbreviations used in this application:

As used herein, the terms “comprises,” “comprising,” “includes,” “including,” “has,” “having,” “contains” or “containing,” or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a composition, a mixture, process, method, article, or apparatus that comprises a list of elements is not necessarily limited to only those elements but may include other elements not expressly listed or inherent to such composition, mixture, process, method, article, or apparatus. Further, unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).

Also, the indefinite articles “a” and “an” preceding an element or component of the invention are intended to be nonrestrictive regarding the number of instances (i.e. occurrences) of the element or component. Therefore “a” or “an” should be read to include one or at least one, and the singular word form of the element or component also includes the plural unless the number is obviously meant to be singular.

The term “invention” or “present invention” as used herein is a non-limiting term and is not intended to refer to any single embodiment of the particular invention but encompasses all possible embodiments as described in the specification and the claims.

As used herein, the term “about” modifying the quantity of an ingredient or reactant of the invention employed refers to variation in the numerical quantity that can occur, for example, through typical measuring and liquid handling procedures used for making concentrates or use solutions in the real world; through inadvertent error in these procedures; through differences in the manufacture, source, or purity of the ingredients employed to make the compositions or carry out the methods; and the like. The term “about” also encompasses amounts that differ due to different equilibrium conditions for a composition resulting from a particular initial mixture. Whether or not modified by the term “about”, the claims include equivalents to the quantities. In one embodiment, the term “about” means within 10% of the reported numerical value, preferably within 5% of the reported numerical value.

The terms “oil reservoir”, and “oil-bearing stratum” may be used herein interchangeably and refer to a subterranean or sub sea-bed formation from which oil may be recovered. The formation is generally a body of rocks and soil having sufficient porosity and permeability to store and transmit oil.

The term “well bore” refers to a channel from the surface to an oil-bearing stratum with enough size to allow for the pumping of fluids either from the surface into the oil-bearing stratum, called an “injection well”, or from the oil-bearing stratum to the surface, called a “production well”.

The terms “denitrifying” and “denitrification” mean reducing nitrate for use in respiratory energy generation.

The term “water flooding” refers to injecting water through well bores into an oil reservoir. Water flooding is performed to flush out oil from an oil reservoir when the oil no longer flows on its own out of the reservoir.

The term “sweep efficiency” relates to the fraction of an oil-bearing stratum that has seen fluid or water passing through it to move oil to production wells during water flooding. One problem that can be encountered with water flooding operations is the relatively poor sweep efficiency of the water, i.e., the water can channel through certain portions of a reservoir as it travels from injection well(s) to production well(s), thereby bypassing other portions of the reservoir. Poor sweep efficiency may be due, for example, to differences in the mobility of the water versus that of the oil, and permeability variations within the reservoir which encourage flow through some portions of the reservoir and not others.

The term “pure culture” means a culture derived from a single cell isolate of a microbial species. The pure cultures specifically referred to herein include those that are publicly available in a depository, and those identified herein.

The term “electron acceptor” refers to a molecular compound that receives or accepts an electron(s) during cellular respiration. Microorganisms obtain energy to grow by transferring electrons from an “electron donor” to an electron acceptor. During this process, the electron acceptor is reduced and the electron donor is oxidized. Examples of acceptors include oxygen, nitrate, fumarate, iron (III), manganese (IV), sulfate or carbon dioxide. Sugars, low molecular weight organic acids, carbohydrates, fatty acids, hydrogen and crude oil or its components such as petroleum hydrocarbons or polycyclic aromatic hydrocarbons are examples of compounds that can act as electron donors.

The term “biofilm” means a film or “biomass layer” of microorganisms. Biofilms are often embedded in extracellular polymers, which adhere to surfaces submerged in, or subjected to, aquatic environments. Biofilms consist of a matrix of a compact mass of microorganisms with structural heterogeneity, which may have genetic diversity, complex community interactions, and an extracellular matrix of polymeric substances.

The term “plugging biofilm” means a biofilm that is able to alter the permeability of a porous material, and thus retard the movement of a fluid through a porous material that is associated with the biofilm.

The term “simple nitrates” and “simple nitrites” refer to nitrate (NO₃ ⁻) and nitrite (NO₂ ⁻), respectively.

The term “bioplugging” refers to making permeable material less permeable due to the biological activity, particlularly by a microorganism.

The term “injection water” refers to fliud injected into oil reservoirs for secondary oil recovery. Injection water may be supplied from any suitable source, and may include, for example, sea water, brine, production water, water recovered from an underground aquifer, including those aquifers in contact with the oil, or surface water from a stream, river, pond or lake. As is known in the art, it may be necessary to remove particulate matter including dust, bits of rock or sand and corrosion byproducts such as rust from the water prior to injection into the one or more well bores. Methods to remove such particulate matter include filtration, sedimentation and centrifugation.

The term “production water” means water recovered from production fluids extracted from an oil reservoir. The production fluids contain both water used in secondary oil recovery and crude oil produced from the oil reservoir.

The term “inoculating an oil well” means injecting one or more microorganisms or microbial populations or a consortium into an oil well or oil reservoir such that microorganisms are delivered to the well or reservoir without loss of viability.

The term “souring” refers to an increase in free sulfide concentration with time, which can be measured by recording the H₂S concentration in the gas phase of a sample.

The present invention relates to methods for reducing sulfide in production fluid that include adding a treatment solution that is an aqueous solution containing nitrate ions or nitrite ions or a mixture of nitrate and nitrite ions, where any of these compositions is herein called a “nitrate/nitrite solution”, to the well casing of an oil production well. In addition, the present invention relates to methods for reducing sulfide in production fluid that include adding a treatment solution that is an aqueous solution containing another strong inorganic oxidizing agent to the well casing of an oil production well. The treatment solution mixes with production fluid containing oil and water whereby sulfide is removed by oxidation. By adding the nitrate/nitrite or other inorganic oxidizing agent-containing treatment solution to the well casing of a production well, a greatly reduced volume of the solution is needed to reduce souring as compared to when injecting a solution into an injection well where it flows into an oil reservoir. In addition, removing sulfide occurs rapidly in the production fluid in the well as compared to slow sulfide removal when injecting a solution into an injection well where it flows into an oil reservoir. An additional benefit is limited biodegradation of oil components during the short residence time in the well pipe.

Nitrate/Nitrite or Other Inorganic Oxidizing Agent-Containing Solution and Treatment

In the present method an aqueous solution containing nitrate ions and/or nitrite ions, or another inorganic oxidizing agent, is added to the well casing of a production well. The total concentration of nitrate and/or nitrite ions, or of other inorganic oxidizing agent, is sufficient to reduce sulfide concentration in production fluid. The ions move, or the other inorganic oxidizing agent moves, by mixing and diffusion into the production fluid of oil and water as shown in one embodiment that is diagrammed in FIG. 1.

The nitrate/nitrite or other inorganic oxidizing agent-containing treatment solution (11) is added into the water production well casing (7) which is inside the well bore (6) drilled through rock layers (2 and 3). A gap exists between the well casing (7) and the face of the rock layer made by the well bore (6). Rock layer (2) represents impermeable rock above and below a permeable rock layer (3) that holds or traps oil. Perforations in the casing (5) allow oil containing production fluid to flow from fractures (4) in the permeable rock (3) into the well casing that extends through the permeable rock that is the oil reservoir (3) near the bottom of the well hole (8). The nitrate/nitrite or other inorganic oxidizing agent-containing solution flows down the well casing outside of the production tubing or production pipe (9) and contacts the oil and water production fluid from the oil reservoir (12) below the production pipe in the well bore as both fluids enter the lower part of the well (14). The volume of nitrate/nitrite or other inorganic oxidizing agent-containing solution that is added is sufficient to fill the well casing. With the height of the nitrate/nitrite or other inorganic oxidizing agent-containing solution in the well casing higher than the natural level of production fluid in the well bore, the concentrated nitrate/nitrite or other inorganic oxidizing agent-containing solution mixes down into the production fluid towards the bottom of the well forming a production fluid mixture containing nitrate ions, nitrite ions, or a mixture of nitrate and nitrite ions or a production fluid mixture containing the other inorganic oxidizing agent. In production mode the production fluid mixed with nitrate/nitrite or other inorganic oxidizing agent-containing solution flows up (1) through the production tubing or production pipe (9) inside the well casing (7) through action of the pump rod with check valves (10). The nitrate/nitrite or other inorganic oxidizing agent-containing treatment solution is thus in contact with the production fluid and removes sulfide from the production fluid as the mixture flows up in the production pipe to the surface and is recovered. Sulfide in the production fluid is removed before it gets to the fluid processing unit on the surface.

Nitrite ions are either supplied in the nitrate/nitrite treatment solution and/or are formed during contact with the production fluid as a product of nitrate ion metabolism by nitrate-reducing bacteria (NRB) in the production fluid. In one embodiment at least a portion of nitrate ions are reduced to nitrite ions by NRB in the production fluid. Sulfide concentration is reduced by direct chemical conversion of sulfide by nitrite (oxidation to sulfur or sulfate). Sulfide concentration is also reduced by promoting growth of sulfide oxidizing nitrate reducing bacteria (SONRB) by nitrate. In addition, production of sulfide is reduced by promoting growth of NRB by nitrate, resulting in reduced growth and therefore activity of sulfate-reducing bacteria (SRB) which produce sulfide.

In mixing of the nitrate/nitrite solution with oil and water production fluid from the reservoir, nitrate and/or nitrite ions diffuse into the production fluid and are diluted. If no nitrite is provided in the nitrate/nitrite solution, nitrite ions are generated by NRB in the well. In the mixture of oil and water production fluid with nitrate/nitrite solution the concentration of nitrite ions (supplied or formed from nitrate) is sufficient to oxidize the majority of sulfide to remove it from the production fluid. In the mixture the concentration of nitrate ions is sufficient to promote growth of nitrate reducing bacteria (NRB) so that dissolved organic carbon (DOC) nutrients are used by NRB instead of by sulfate-reducing bacteria (SRB) to reduce new production of sulfide.

In one embodiment the nitrite concentration following mixing of the nitrate/nitrite solution with oil and water production fluid from the oil reservoir is at least about 5-fold greater than the concentration of sulfide in the production fluid in the well. Applicants have found that a ratio of at least about 5:1 of nitrite ions:sulfide ions (NO₂ ⁻:S²⁻) supports rapid oxidation of the sulfide, as shown herein in Example 2. The concentration of sulfide in the oil and water production fluid of an oil reservoir may be readily measured by one skilled in the art, for example, by using a colorimetric assay based on methylene blue formation (Cline (1969) Limnol. Oceanogr. 14:454-458) or a paper strip assay such as Hydrogen Sulfide Test strips (#481197-1, Industrial Test Systems, Inc., Rock Hill, S.C. USA).

Mixing of the nitrate/nitrite solution from the well casing with the oil and water production fluid in the well below the production pipe will dilute the nitrate/nitrite solution. The rate and amount of dilution will depend on factors including the method of adding the solution to the well casing (such as pulse, continuous, or single addition), and the density of the production fluid in the bottom of the well. Typically dilution may be by about 1-fold to about 5-fold or more. The concentration of nitrate and/or nitirite ions in the solution added to the well casing may be adjusted to accommodate any dilution factor. For example, with 5-fold dilution in order to have a final 5:1 ratio of NO₂ ⁻:S²⁻, a 25-fold higher molar concentration of nitrite than sulfide in the oil and water production fluid is needed in the nitrate/nitrite solution. The nitrite may be supplied in the nitrate/nitrite solution directly, or formed by reduction of nitrate by NRB. Thus for sulfide oxidation, the total molar concentration of nitrate and/or nitrite ions in the nitrate/nitrite solution is 25-fold greater than the molar concentration of sulfide in the production fluid. For example, when treating an oil reservoir with production fluid having a sulfide concentration of about 25 ppm or 0.78 mMoles per liter and based on having a 5-fold excess of nitrite ions and a 5-fold dilution factor, a nitrate/nitrite solution added to the well casing has a total concentration of nitrate and/or nitrite ions of at least about 897 ppm or 19.5 mMoles per liter.

Additional nitrate may be included in the nitrate/nitrite solution to promote growth of NRB so that available carbon source in production fluid is used up by NRB thereby suppressing growth and production of sulfide by SRB. For example, about 93 ppm nitrate would be used in metabolism of about 50 ppm glucose, as calculated based on the assumption that all glucose carbon is converted to carbon dioxide. Again assuming a 5-fold dilution of the nitrate/nitrite solution in mixing with production fluid in the well below the production pipe, about 465 ppm of nitrate would support growth of NRB to metabolize 50 ppm of available carbon source.

In addition, native or introduced populations of a specialized type of sulfide oxidizing, nitrate reducing organisms (SONRB), which rely on sulfide oxidation to generate energy for growth, rather than oxidation of organic material, such as glucose used in the example above, may be present in the treated zone of the well. Growth and metabolism of SONRB are supported by the nitrate provided in the nitrate/nitrite solution. These bacteria may contribute to reducing the amount of sulfide in production fluid such that the concentration of nitrite needed to oxidize sulfide is reduced. Thus a lower amount of nitrite ions, or nitrate ions that are reduced to nitrite ions by NRB, is needed in the presence of SONRB.

Maximum concentrations of nitrate and/or nitrite ions used would be determined by the desired treatment goal as determined by one skilled in the art controlling well souring. In one embodiment to support both effects of oxidizing sulfide already present and reducing new production of sulfide, the nitrate/nitrite solution has a combined concentration of nitrate and/or nitrite ions of at least about 700 ppm. Typically excess concentration is used. The nitrate and/or nitrite combined concentration may be about 800, 900, 1000 ppm or more, up to a limit where toxic effects of the salts on the desired microbial populations becomes an issue, which is approximately 1500 ppm for nitrite and 3000 ppm for nitrate. In another embodiment, to maximize sulfide oxidation capacity where toxicity to microorganisms is not a concern, nitrite concentrations in excess of 100,000 ppm may be used as limited by concentrations that do not adversely corrode metal parts of the system and/or cause problems in down stream oil processing.

The nitrate/nitrite solution may be made using nitrate ions and/or nitrite ions in any form that are released in solution, such as in any soluble salt form such as calcium, sodium, potassium, ammonium, and any combination mixtures of salts. Typically sodium salts of nitrate and/or nitrite are used. These salts are dissolved in an aqueous solution from any suitable source such as for example, sea water, brine, production water, water recovered from an underground aquifer, including those aquifers in contact with the oil, or surface water from a stream, river, pond or lake. As is known in the art, it may be desired to remove particulate matter including dust, bits of rock or sand and corrosion by-products such as rust from the water prior to use in a treatment solution. Methods to remove such particulate matter include filtration, sedimentation and centrifugation.

An aqueous solution of the present method may contain a different inorganic oxidizing agent, other than nitrate/nitrite. The inorganic oxidizing agent may be any water soluble strong inorganic oxidizing agent, with strong meaning that the inorganic oxidizing agent has reaction standard half-cell potential of greater than −0.478 volts. One of skill in the art will be familiar with, or can readily identify, a strong inorganic oxidizing agent, examples of which include, but are not limited to, permanganates, persulfates, inorganic peracids, chromates, bromates, iodates, chlorates, perchlorates, chlorites, hypochlorites, inorganic peroxides, and certain oxides. Some specific examples include ammonium dichromate, ammonium perchlorate, ammonium permanganate, barium bromate, barium chlorate, barium peroxide, cadmium chlorate, calcium chlorate, calcium chromate, calcium perchlorate, chlorine dioxide, potassium persulfate, and hydrogen peroxide. In one embodiment the inorganic oxidizing agent is chlorine dioxide, hypochlorite, persulfate, or hydrogen peroxide. At least one inorganic oxidizing agent is included in the aqueous solution. Typically oxidizing agents are used separately.

In mixing of the inorganic oxidizing agent-containing solution with oil and water production fluid from the reservoir, the agent diffuses into the production fluid and is diluted. In the mixture of oil and water production fluid with the inorganic oxidizing agent-containing solution, the concentration of the agent is sufficient to oxidize the majority of sulfide to remove it from the production fluid. Sulfide is directly oxidized by the agent by direct chemical conversion of sulfide to sulfur or sulfate.

In one embodiment the inorganic oxidizing agent concentration following mixing of the inorganic oxidizing agent-containing solution with oil and water production fluid from the oil reservoir is at least about 1.5 to 6 times greater than the concentration of sulfide in the production fluid in the well. The agent concentration may be at least about 1.5, 2, 2.5, 3, 3.5, 4, 4.5, 5, 5.5, or 6 times greater than the concentration of sulfide in the production fluid in the well. The exact agent concentration needed to oxidize the majority of the sulfide may be readily determined for a specific agent by one skilled in the art, as shown in examples herein for chlorine dioxide, potassium persulfate, and hydrogen peroxide. It is found herein that ratios of 1.71:1, 5.3:1, and 3.76:1 are effective in causing rapid and complete or almost complete oxidation of sulfide by these agents, respectively. The concentration of sulfide in the oil and water production fluid of an oil reservoir may be readily measured by one skilled in the art, for example, by using a colorimetric assay based on methylene blue formation (Cline (1969) Limnol. Oceanogr. 14:454-458) or a paper strip assay such as Hydrogen Sulfide Test strips (#481197-1, Industrial Test Systems, Inc., Rock Hill, S.C.).

Mixing of the inorganic oxidizing agent-containing solution from the well casing with the oil and water production fluid in the well below the production pipe will dilute the agent solution. The rate and amount of dilution will depend on factors including the method of adding the solution to the well casing (such as pulse, continuous, or single addition), and the density of the production fluid in the bottom of the well. Typically, dilution may be by about 1-fold to about 5-fold or more. The concentration of inorganic oxidizing agent in the solution added to the well casing may be adjusted to accommodate any dilution factor. For example, with 5-fold dilution in order to have a final 1.5:1 ratio of chlorine dioxide to sulfide (ClO₂:S²⁻), a 7.55-fold higher molar concentration of agent than sulfide in the oil and water production fluid is needed in the agent-containing solution. Thus for sulfide oxidation, the total molar concentration of the chlorine dioxide in the chlorine dioxide containing solution added is 7.5-fold greater than the molar concentration of sulfide in the production fluid. For example, when treating an oil production well containing production fluid having a sulfide concentration of about 25 ppm or 0.78 mMoles per liter and based on having a 1.5-fold excess of chlorine dioxide and a 5-fold dilution factor, a chlorine dioxide-containing solution added to the well casing has a total concentration of chlorine dioxide of at least about 394.29 ppm [7.5×0.78=5.85 mMoles ClO₂; 5.85×67.4 (Mwt of ClO₂)=394.29 ppm] or 5.85 mMoles per liter.

The inorganic oxidizing agent-containing solution may be made using any of the agents, as exemplified above, in a form that is soluble in water. The agent is dissolved in an aqueous solution from any suitable source such as for example, sea water, brine, production water, water recovered from an underground aquifer, including those aquifers in contact with the oil, or surface water from a stream, river, pond or lake. As is known in the art, it may be desired to remove particulate matter including dust, bits of rock or sand and corrosion by-products such as rust from the water prior to use in a treatment solution. Methods to remove such particulate matter include filtration, sedimentation and centrifugation. The nitrate/nitrite or other inorganic oxidizing agent-containing solution is first added to the well casing prior to producing from the well. Typically the first addition is just prior to producing from the well. Addition of the nitrate/nitrite or other inorganic oxidizing agent-containing solution to the well casing of a production well may be by any method typically used to add fluids to the well casing such as by pumping. The nitrite/nitrate or other inorganic oxidizing agent-containing solution may be added to the well casing only once, or intermittently by periodic filling of the well casing before and during production from the well (pulsed). Alternatively the nitrite/nitrate or other inorganic oxidizing agent-containing solution may be added to the well casing continuously by continuous introduction of the solution into the well casing at the top of the production well casing at the surface, before and during production from the well.

In one embodiment there is a separate delivery tubing or pipe within the well casing that is outside of the production tubing or production pipe. This delivery tubing extends from the surface to the lower part of the well to deliver the nitrate/nitrite or other inorganic oxidizing agent-containing solution to the point where it mixes with the production fluid below the production pipe. Though this system for addition requires a separate tubing, it allows more specific control of the concentration of nitrate and/or nitrite ions, and of another inorganic oxidizing agent, delivered to the production fluid.

The nitrate/nitrite or other inorganic oxidizing agent-containing solution may be added alone, or as a mixture with one or more other fluids added to the well casing. When mixed with other fluids, the final nitrite and nitrate ion concentrations, or other inorganic oxidizing agent concentration, in the mixture are those described above. For example, nitrite and nitrate ions or other inorganic oxidizing agent may be added to power water used to drive a jet type production well pump. A more concentrated nitrate/nitrite or other inorganic oxidizing agent-containing solution may be prepared and diluted into another fluid to be added to the well casing.

The nitrate/nitrite or other inorganic oxidizing agent-containing solution may be added to the casing of a production well that is a single well oil recovery system or a production well in a multiple well oil recovery system. In a single well oil recovery system the production well is alternately the production well and the injection well. This type of well is typically used in a “Huff and Puff” process. For this type of well and process, the nitrate/nitrite or other inorganic oxidizing agent-containing solution is typically added to the well casing after a well treatment is injected or introduced to the well when the well is returned to production. In a multiple well system, the nitrate/nitrite or other inorganic oxidizing agent-containing solution is typically added to the production well casing prior to and/or during the period when production fluids are being recovered.

Combination of Nitrate/Nitrite or Other Inorganic Oxidizing Agent-Containing Solution and MEOR Treatments

The present method may be used in oil reservoirs where microbially enhanced oil recovery (MEOR) methods (Brown, L. R., Vadie, A. A,. Stephen, O. J. SPE 59306, SPE/DOE Improved Oil Recovery Symposium, Oklahoma, Apr. 3-5, 2000) are practiced. MEOR methods are used to improve oil recovery by the actions of microorganisms in an oil reservoir, which may include releasing oil from substrates and/or plugging highly permeable zones by formation of plugging biofilms. MEOR methods include injecting oil reservoirs with nutrient solutions that support microbial growth, and also may include inoculation of oil reservoirs with one or more microorganisms as disclosed for example in U.S. Pat. No. 7,776,795, U.S. Pat. No. 7,708,065, and commonly owned and co-pending US Pat. Appl. Pub. #20090263887, which are each incorporated herein by reference. Thus when using MEOR the production fluid may contain relatively higher levels of one or more carbon substrates to support growth of indigenous microorganisms. Carbon substrates may be in excess in the oil reservoir, and in the oil and water mixture that enters the well becoming production fluid. When microorganisms are introduced in MEOR, there may be higher levels of microorganisms, and/or different populations of microorganisms, than without MEOR.

When higher levels of carbon substrates are present in production fluid, and SRB are present, higher levels of sulfide may be present in production fluid than encountered when not injecting a nutrient solution in a MEOR process. It is thus of particular importance to remove sulfide and reduce growth and production of sulfide by SRB that thrive on the injected nutrients when a MEOR process is used in an oil reservoir. When using a MEOR treatment, the nitrate/nitrite or other inorganic oxidizing agent-containing solution is first added to the well casing of a production well after the MEOR treatment to the production well or to an injection well in the same oil reservoir and connected to the production well, but prior to producing from the well.

Depending on the sulfide concentration in the production fluid, it may be advised to use higher concentrations of nitrate and/or nitrite ions in a nitrate/nitrite solution or other inorganic oxidizing agent in solution in conjunction with a MEOR process. The concentration needed may be determined by one skilled in the art by analysis of the concentration of sulfide in production fluids, and following ratios described above.

EXAMPLES

The present invention is further defined in the following Examples. It should be understood that these Examples, while indicating preferred embodiments of the invention, are given by way of illustration only. From the above discussion and these Examples, one skilled in the art may ascertain the essential characteristics of this invention, and without departing from the spirit and scope thereof, may make various changes and modifications of the invention to adapt it to various usages and conditions.

General Methods

The meaning of abbreviations are used in this application are as follows: “hr” means hour(s), “min” means minute(s), “day” means day(s), “mL” means milliliters, “mg/mL” means milligram per milliliter, “L” means liters, “μL” means microliters, “mM” means millimolar, “μM” means micromolar, “nM” means nano molar, “μg/L” means microgram per liter, “pmol” means picomol(s), “° C.” means degrees Centigrade, “° F.” means degrees Fahrenheit, “mm” means millimeter, “ppm” means part per million, “g/L” means gram per liter, “mL/min” means milliliter per minute, “mL/hr” means milliliter per hour, “g” means gram, “mg/L” means milligram per liter,”

Sulfide Analysis

Sulfide analysis was done using the methylene blue colorimetric assay with optical density read at 670 nm as described in (Cline (1969) Limnol. Oceanogr. 14:454-458).

Example 1 NO₂ ⁻ Reactivity with Sulfide

A sodium nitrite solution was used to oxidize a sodium sulfide solution at room temperature in a closed system in order to look at the kinetics of the reaction and to prevent the volatilization of sulfide. Based on a balanced redox reaction, 1 mole of nitrite should be able to oxidize at least 0.5 mole of hydrogen sulfide. The nitrite and sulfide solutions used in the experiment were made up in artificial brine, which mimics the moderately high salinity of many oil reservoirs. The brine had the following composition: CaCl₂.2H₂O, 6.75 g, NaCl, 26.1 g, Na₂SO₄, 0.015 g, MgCl₂.6H₂O g, 4.45, KCl, 0.7 g plus enough water to make a total of 500 ml of brine solution. The sulfide solution in brine was approximately 15 ppm S²⁻. The nitrite solutions were approximately 50 ppm and 725 ppm NO₂ ⁻. Two different treatments were run. In treatment 1 (Table 1) the nitrite:sulfide molar ratio was 29:1, which resulted in reaction conditions where nitrite was approximately 14.5 (i.e. 29/2) fold in excess of the nominal concentration needed to oxidize all sulfide in the reaction vessel. In treatment 2 (Table 1) the nitrite/sulfide molar ratio was 2.1:1, which resulted in reaction conditions where nitrite was approximately 1.05 (i.e. 2.1/2) fold in excess of the nominal concentration needed to oxidize all sulfide in the the 26 ml crimp-cap-sealed glass reaction vessel. The sulfide remaining was assayed as described in General Methods at 10 min and 120 min of reaction time and the results are given in Table 1.

Although both treatments had enough nitrite to oxidize all of the sulfide present based on the redox balanced equation, only treatment 1 showed complete removal of sulfide at the 10 minute and 2 hour observation time points (Table 1). These data show that in order to have the oxidation reaction occur rapidly the nitrite:sulfide ratio should be in excess of 2.1:1.

TABLE 1 Changes in sulfide concentrations with time following the addition of nitrite. Observed NO₂ ⁻:S²⁻ ppm S²⁻ molar ppm S²⁻ following Expected Treat- ratio in Reaction added NO₂ ⁻ ppm S²⁻ after ment reactor Time, min to reactor addition NO₂ ⁻ addition 1 29 10 19 0 0 120 19 0 0 2 2.1 10 19 15 0 120 19 15 0

Example 2 NO₂ ⁻ Reactivity with Sulfide: Titration of Molar Ratios Needed for a Rapid Reaction

A range of nitrite:sulfide ratios were tested to determine the molar ratio needed to cause a rapid oxidation of sulfide. The nitrite and sulfide solutions used in the experiments were made up in artificial brine as described in Example 1. Experiments were performed as described in Example 1 using eight different treatments. The nitrite/sulfide molar ratios used were 2, 5, 10, 15, 20, 25, 30, and 35. Results given in Table 2 showed that the reaction rate remained slow at a ratio of 2, as seen in the previous Example, but at a ratio of 5:1 or higher the reaction occurred rapidly with sulfide becoming undetectable in 10 minutes or less. The ability to rapidly remove sulfide at lower nitrite:sulfide ratios makes the process more economical

TABLE 2 Changes in sulfide concentrations with time following the addition of nitrite at NO₂ ⁻:S²⁻ ratios from 2:1 to 35:1. ppm S²⁻ Observed ppm NO₂ ⁻:S²⁻ molar Reaction added S²⁻ following ratio in reactor Time, min to reactor NO₂ ⁻ addition  2:1 10 26 8.9 120 26 3.8  5:1 10 26 0 120 26 0 10:1 10 26 0 120 26 0 15:1 10 26 0 120 26 0 20:1 10 26 0 120 26 0 25:1 10 26 0 120 26 0 30:1 10 26 0 120 26 0 35:1 10 26 0 120 26 0

Example 3 Prophetic Production Well Treatment Using Continuous Addition of Nitrate/Nitrite Solution in Well Casing to Mitigate Sulfide Present in Production Fluid of Soured Wells

In this example, a producer well is continuously treated to mitigate sulfide present in the production water using a nitrate/nitrite mixture. Sulfide in the production fluids often results from well souring, following the start of water injection for secondary oil recovery. Rather than treating the injected water and all reaches of the subterranean oil reservoir, as is the normal practice to mitigate souring by sulfide formation, a process is used that treats the smaller produced water volume, making it more economical, while still sweetening the produced fluids by removing sulfide.

A nitrate/nitrite solution is produced by dissolving any inexpensive nitrate and nitrite salts, such as NaNO₂ or NaNO_(3,) in water. This solution is continuously pumped into the well casing of a production well. The production fluid flow entrains the casing solution of nitrate/nitrite into the production fluid moving up the well pipe or, in the case of a jet pump, the nitrate/nitrite solution is incorporated into the power water, which joins the produced fluid flow after passing through the jet pump drive. The nitrate/nitrite mixture contains nitrite (NO₂ ⁻) at a molar ratio of approximately 25:1 with respect to the molar concentration of sulfide (S²⁻) in the produced water and contains nitrate at a concentration of about 7.5 mMoles NO₃ ⁻/L per 50 ppm of dissolved organic carbon (DOC) in the production water. This fluid is pumped down the casing at a rate such that the nitrate/nitrite solution is entrained into the production fluids at a ratio of at most 5 parts production fluids per 1 part nitrate/nitrite solution.

Two production wells in a soured field are found to contain approximately 25 ppm S²⁻ and 50 ppm DOC. A solution containing 900 ppm NO₂ ⁻+465 ppm NO₃ ⁻ is pumped into the well casing to treat one of the wells as described above. After a week, S²⁻ concentration is observed to have dropped to 5 ppm, and a week later sulfide is found to be undetectable in the treated well. The neighboring, untreated production well, producing oil from the same soured reservoir, is observed to still contain approximately 25 ppm S²⁻ in its produced water after the same two week period.

Example 4 Prophetic Nitrate/Nitrite Treatment Combined with a MEOR Process that Utilizes Organic Nutrients

In this example, a producer well is treated for microbial enhanced oil recovery using an organic nutrient. A solution of 100 ppm yeast extract plus 4000 ppm of disodium malate is fed batch wise to an oil reservoir through a production well. This is accomplished by pumping this nutrient solution down the casing of the well and into the oil reservoir. The intent of this treatment is to improve oil recovery from this single well. After pumping these nutrients into the reservoir, the oil well is shut in for a period of 2 weeks while the microbial population in the well consumes the malate carbon substrate. Analysis of water in the reservoir and of the injection water pumped into the reservoir before and after the nutrient treatment show that there are sulfate reducing bacteria present and that there is 100 ppm sulfate in these waters. It is therefore anticipated that some sulfide will be produced from the sulfate reducing bacteria metabolizing the malate or metabolic byproducts of the malate. After the 14 day shut in and just before the well is put back onto production, a solution of 1 wt % nitrate and 6.5 wt % nitrite is pumped into the well casing. The volume of this solution is enough to fill the well casing. The well is then put back on production. The nitrate/nitrite solution in the well casing becomes mixed with the production fluids and analysis of the well effluent shows no signs of sulfide in the produced water.

In contrast, an identical nearby production well producing oil from the same reservoir is treated in the exact same fashion without the nitrate/nitrite post treatment. It is observed that there is 50 ppm of sulfide present in the water produced by this well when this well was put back on production. Both wells show a substantial increase in oil production amounting to an extra 30% increase in production rate for a period of a month after the MEOR treatment.

Example 5 Chlorine Dioxide Removal of Sulfide: Titration of Molar Ratios Needed for a Rapid Reaction

A range of chlorine dioxide:sulfide ratios was tested to determine the molar ratio needed to cause a rapid oxidation and removal of sulfide. The chlorine dioxide and sulfide solutions used in the experiments were made up in artificial brine as described in Example 1. Experiments were performed as described in Example 1 using five different treatments and testing for sulfide remaining after 10 min of reaction time. The chlorine dioxide:sulfide molar ratios (ClO₂, M:S²⁻, M) used were appproximately 0.11:1, 0.29:1, 0.57:1, 1.7:1, and 3.42:1. Results given in Table 3 showed that sulfide at 100 mg/L concentraton was rapidly and completely removed with the ClO₂:S²⁻ molar ratio of approximately 1.71:1. At this ratio of reactants and above the sulfide concentration dropped from 100 ppm to undetectable in 10 minutes or less.

TABLE 3 Changes in sulfide concentrations after a10 minute reaction time following the addition of chlorine dioxide at various molar ratios. mg/L S²⁻ Observed mg/L ClO₂:S²⁻ molar Reaction added S²⁻ following ratio in reactor Time, min to reactor ClO₂ addition 0.11:1 10 100 79.6 0.29:1 10 100 56.4 0.57:1 10 100 21.4 1.71:1 10 100 0.0 3.42:1 10 100 0.0

Example 6 Persulfate Removal of Sulfide: Titration of Molar Ratios Needed for a Rapid Reaction

Using a solution of potassium persulfate, a range of persulfate:sulfide ratios was tested to determine the molar ratio needed to cause a rapid oxidation and removal of sulfide. The potassium persulfate and sulfide solutions used in the experiments were made up in artificial brine as described in Example 1. Experiments were performed as described in Example 1 using seven different treatments with replication and testing for sulfide remaining after 10 min of reaction time. The persulfate:sulfide (S₂O₈ ²⁻:S²⁻) molar ratios used were 0.1:1, 0.2:1, 0.3:1, 0.7:1, 1.3:1, 2.7:1, and 5.3:1. Results given in Table 4 showed that at the highest ratio of oxidant (persulfate) to sulfide that was tested, 5.3:1, the 100 mg/L sulfide concentraton was greatly reduced, but not reduced to an undetectable concentration. This shows that a molar ratio exceeding 5.3 is needed to rapidly and completely remove sulfide present at a concentration of 100 mg/L.

TABLE 4 Changes in sulfide concentrations after a10 minute reaction time following the addition of a persulfate solution at various molar ratios. mg/L S²⁻ Observed mg/L S₂O₈ ²⁻:S²⁻ molar Reaction added S²⁻ following ratio in reactor Time, min to reactor S₂O₈ ²⁻ addition 0.1:1 10 100 101.9 0.1:1 10 100 97.4 0.2:1 10 100 96.7 0.2:1 10 100 94.5 0.3:1 10 100 76.7 0.3:1 10 100 78.0 0.7:1 10 100 24.5 0.7:1 10 100 25.8 0.7:1 10 100 40.3 0.7:1 10 100 40.2 1.3:1 10 100 14.8 1.3:1 10 100 15.4 1.3:1 10 100 19.8 1.3:1 10 100 20.6 2.7:1 10 100 9.2 2.7:1 10 100 8.6 5.3:1 10 100 3.7 5.3:1 10 100 3.0

Example 7 Hydrogen Peroxide Removal of Sulfide: Titration of Molar Ratios Needed for a Rapid Reaction

A range of hydrogen peroxide:sulfide ratios was tested to determine the molar ratio needed to cause a rapid oxidation and removal of sulfide. The hydrogen peroxide and sulfide solutions used in the experiments were made up in artificial brine as described in Example 1. Experiments were performed as described in Example 1 using five different treatments and testing for sulfide remaining after 10 min of reaction time. The hydrogen peroxide:sulfide (H₂O₂:S²⁻) molar ratios used were approximately 0.19:1, 0.47:1, 0.94:1, 1.88:1, and 3.76:1. Results given in Table 5 showed that sulfide at 100 mg/L concentraton was rapidly and completely removed with the H₂O₂:S²⁻ molar ratio of approximately 3.76:1. At this ratio of reactants the sulfide concentration dropped from 100 ppm to undetectable in 10 minutes or less.

TABLE 5 Changes in sulfide concentrations after a 10 minute reaction time following the addition of hydrogen peroxide at various molar ratios mg/L S²⁻ Observed mg/L H₂O₂:S²⁻ molar Reaction added S²⁻ following ratio in reactor Time, min to reactor H₂O₂ addition 0.19:1 10 100 72.2 0.47:!  10 100 42.8 0.94:1 10 100 23.4 1.88:1 10 100 2.5 3.76:1 10 100 0.0 

What is claimed is:
 1. A method for treating production fluid in an oil production well comprising: a) providing an oil production well in an oil reservoir having a well casing and a production pipe; b) adding an aqueous solution comprising at least one inorganic oxidizing agent to the well casing wherein said solution flows down the well casing and contacts production fluid in the well bore below the production pipe; and c) producing the production fluid through the production pipe; wherein the sulfide concentration in the production fluid is reduced as compared to the sulfide concentration in production fluid obtained with omission of step (b).
 2. The method of claim 1 wherein the inorganic oxidizing agent has a reaction standard half-cell potential that is greater than −0.478 volts.
 3. The method of claim 2 wherein the inorganic oxidizing agent is selected from the group consisting of permanganates, persulfates, inorganic peracids, chromates, bromates, iodates, chlorates, perchlorates, chlorites, hypochlorites, inorganic peroxides, and oxides
 4. The method of claim 3 wherein the inorganic oxidizing agent is selected from the group consisting of chlorine dioxide, hypochlorite, persulfate, and hydrogen peroxide.
 5. The method of claim 1 wherein the inorganic oxidizing agent comprises nitrate ions, nitrite ions, or a mixture of nitrate and nitrite ions.
 6. The method of claim 5 wherein the total molar concentration of nitrate ions, nitrite ions, or the mixture of nitrate and nitrite ions is at least about five-fold higher than the molar concentration of sulfide in production fluid of the production well measured prior to addition of the aqueous solution of (b).
 7. The method of claim 5 wherein at least a portion of nitrate ions are reduced to nitrite ions in the production fluid mixture by nitrate reducing bacteria.
 8. The method of claim 1 wherein the oil production well of (a) is a single well oil recovery system or in a multiple well oil recovery system.
 9. The method of claim 1 wherein prior to step (b) the oil reservoir is injected with a nutrient solution and optionally with at least one microorganism.
 10. The method of claim 1 wherein the aqueous solution of (b) is combined with power water added to the well casing.
 11. The method of claim 1 wherein adding the aqueous solution to the well casing in (b) is intermittent or continuous, starting prior to producing from the well.
 12. The method of claim 1 wherein the oil production well has a delivery tubing in side the well casing and outside of the production pipe, and the aqueous solution of (b) is added to the delivery tubing.
 13. The method of claim 5 wherein the aqueous solution comprises nitrite ions.
 14. The method of claim 13 wherein the aqueous solution comprises nitrite ions and omits nitrate ions.
 15. The method of claim 2 wherein the total molar concentration of the inorganic oxidizing agent is at least about 1.5-fold higher than the molar concentration of sulfide in production fluid of the production well measured prior to addition of the aqueous solution of (b). 